Fields of Disclosure
The disclosure relates generally to the field of fluid separation. More specifically, the disclosure relates to the cryogenic separation of contaminants, such as acid gas, from a hydrocarbon.
Description of Related Art
This section is intended to introduce various aspects of the art, which may be associated with the present disclosure. This discussion is intended to provide a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The production of natural gas hydrocarbons, such as methane and ethane, from a reservoir oftentimes carries with it the incidental production of non-hydrocarbon gases. Such gases include contaminants, such as at least one of carbon dioxide (“CO2”), hydrogen sulfide (“H2S”), carbonyl sulfide, carbon disulfide and various mercaptans. When a feed stream being produced from a reservoir includes these contaminants mixed with hydrocarbons, the stream is oftentimes referred to as “sour gas.”
Many natural gas reservoirs have relatively low percentages of hydrocarbons and relatively high percentages of contaminants. Contaminants may act as a diluent and lower the heat content of hydrocarbons. Some contaminants, like sulfur-bearing compounds, are noxious and may even be lethal. Additionally, in the presence of water some contaminants can become quite corrosive.
It is desirable to remove contaminants from a stream containing hydrocarbons to produce sweet and concentrated hydrocarbons. Specifications for pipeline quality natural gas typically call for a maximum of 2-4% CO2 and ¼ grain H2S per 100 scf (4 ppmv) or 5 mg/Nm3 H2S. Specifications for lower temperature processes such as natural gas liquefaction plants or nitrogen rejection units typically require less than 50 ppm CO2.
The separation of contaminants from hydrocarbons is difficult and consequently significant work has been applied to the development of hydrocarbon/contaminant separation methods. These methods can be placed into three general classes: absorption by solvents (physical, chemical and hybrids), adsorption by solids, and distillation.
Separation by distillation of some mixtures can be relatively simple and, as such, is widely used in the natural gas industry. However, distillation of mixtures of natural gas hydrocarbons, primarily methane, and one of the most common contaminants in natural gas, carbon dioxide, can present significant difficulties. Conventional distillation principles and conventional distillation equipment are predicated on the presence of only vapor and liquid phases throughout the distillation tower. The separation of CO2 from methane by distillation involves temperature and pressure conditions that result in solidification of CO2 if a pipeline or better quality hydrocarbon product is desired. The required temperatures are cold temperatures typically referred to as cryogenic temperatures.
Certain cryogenic distillations can overcome the above mentioned difficulties. These cryogenic distillations provide the appropriate mechanism to handle the formation and subsequent melting of solids during the separation of solid-forming contaminants from hydrocarbons. The formation of solid contaminants in equilibrium with vapor-liquid mixtures of hydrocarbons and contaminants at particular conditions of temperature and pressure takes place in a controlled freeze zone section. A lower section may also help separate the contaminants from the hydrocarbons but the lower section is operated at a temperature and pressure that does not form solid.
Often times the feed stream separated in a distillation tower having a controlled freeze zone section is first introduced into the distillation tower via the lower section regardless of the amount of CO2 in the feed stream.
Disadvantages may arise when the feed stream is first introduced into the lower section regardless of the amount of CO2 in the feed stream. Disadvantages may include a distillation tower that is not optimally sized. Disadvantages may include a distillation tower that does not use energy efficiently. These disadvantages may arise because the distillation tower may be using more energy and/or space than necessary to process a feed stream when the amount of CO2 in the feed stream is not properly considered before introducing the feed stream into the distillation tower.
Disadvantages may arise because solids may adhere to an internal (e.g. the controlled freeze zone wall) of the controlled freeze zone section rather than falling to the bottom of the controlled freeze zone section. The adherence, if uncontrolled, can interfere with the proper operation of the controlled freeze zone section and the effective separation of methane from contaminants.
A need exists for improved technology for separating a feed stream that optimally matches where the feed stream should enter the distillation tower based on the concentrations of components in the feed stream so as to optimize energy efficiency and/or the size of the distillation tower.